Retrievable well packer



Feb 11, 1969 D. E. YOUNG RETRIEVABLE WELL PACKER Filed Aug. 10, 1967 1 f/gl/A INVENTOR.

Feb. 11, 1969 o. E. YOUNG RETRIEVABLE WELL PACKER Filed Aug. 10, 1967 INVENTOR.

BY jyag) AT OP/VEV Feb. 11, 1969 D. E. YOUNG 3,425,845

RETRIEVABLE WELL PACKER Filed Aug- 10, 1967 Sheet .2 of 5 United States Patent 8 Claims ABSTRACT OF THE DISCLOSURE The particular embodiment described herein as illustrative of one form of the invention is a well packer apparatus having a mandrel which is subject to fluid pressure in a well. A force balancing system for the mandrel includes piston and cylinder means for minimizing the net force on the mandrel when the high pressure is in favor of either the tubing or the annulus.

This invention relates generally to subsurface well tools and more particularly to a new and improved retrievable well packer apparatus for packing off a well bore.

A typical retrievable well packer which can be used in the performance of multiple operations in a well such as fracturing, acidizing, squeezing, and testing normally includes slips and packing which are expanded for respectively anchoring against movement in a well casing and packing off the annulus between the well casing, and a running-in string of tubing or drill pipe on which the well packer is lowered into the well. A fluid bypass can be provided which is closed during such operations and which can be opened to equalize fluid pressures on the packer after the particular operation is completed and permit retrieval of the packer. With the slips and packing expanded and the bypass closed, the well interval below the packer is isolated and the tubing string provides access to the interval from the top of the well bore. This general type of well packer can be used with a valved device as shown in US. Patent No. 3,065,796 to Nutter for performing such multiple operations in a well.

During the aforementioned operations, it is quite common for high pressure differentials between fluids in the running-in string and in the well annulus above the packer to act as very high and substantial forces on parts of the packer. Such forces can act either upwardly on the packer mandrel tending to open the bypass valve when the higher pressure is in favor of the tubing so that there is the problem of premature loss of the packer seat. Accordingly, it has become standard practice in the art to provide a balance piston on the mandrel on which the higher tubing pressure can act to hold the mandrel down. However, situations can arise where the higher pressure is in favor of the annulus and impose force downwardly on the mandrel so that a very high strain must be taken on the running-in string at the surface in order to open the bypass valve and unset the packer when desired.

This later situation is quite extreme during dry testing procedures where atmospheric or other relatively low pressure exists below the packer for the purpose of testing a bridge plug or the like to determine whether the bridge plug is functioning properly. Also, this situation can arise unexpectedly where a zone below the packer is tested and the zone fails to produce in any significant amounts and there is no pressure build-up. The imposition of such downward force on the mandrel has placed limits on the depth at which the packer can be safely used and still permit retrieval of the packer when desired without incurring risks of exceeding the allowable strain strength of the tubing.

An object of the present invention is to provide a new and improved well packer of the type described having a force balancing mechanism which is operative in such a manner that there is no substantial net force on the mandrel due to pressure differential between annulus pressures and tubing pressures, regardless of whether the higher pressure is in favor of the tubing or the annulus, thereby enabling more effective packer operation under extreme pressure conditions than has heretofore been known in the art.

Another object of the present invention is to provide a new and improved retrievable well packer apparatus having a force balancing system which permits greater setting depths for the packer, even under the severe pressure conditions of dry testing.

Another object of this invention is to provide a new and improved force balancing system for a retrievable well packer which is compact in design and foolproof in operation and highly effective in minimizing the net force on the packer mandrel whether the high pressure is in favor of the tubing or the annulus.

Still another object of the present invention is to provide a new and improved well packer apparatus having the foregoing advantageous features and which is simple and reliable in operation and which will require less maintenance than previous tools of this general type.

These and other objects are attained in accordance with the concepts of the present invention by providing, in a retrievable well packer having a packing assembly and a mandrel telescopically movable in the packing assembly and adapted for connection to a tubing string extending to the top of a well bore, first and second piston and cylinder means. A passage is provided to enable tubing pressure to act downwardly on the first piston means which is on the mandrel. Other passages are provided to enable annulus pressures to act downwardly on the second piston means as well as upwardly on the first piston means, downward force on the second piston means being also transferable to the mandrel. The first and second piston means along with their respective cylinders are relatively sized and arranged such that there is no substantial net force on the mandrel when high tubing pressures are acting on the system or, 'on the other hand, when high annulus pressures are exerting force on the system.

The present invention has other objects and advantages which will become more clearly apparent in connection with the following detailed description. The novel features of the present invention being set forth with particularity in the appended claims, the operation together with further objects and advantages thereof, may best be understood by way of illustration and example of a preferred embodiment when taken in conjunction with the accompanying drawings, in which:

FIGURES 1A and 1B are longitudinal sectional views, with portions in side elevation, of a well packer apparatus in accordance with the principles of the present invention and with parts in retracted positions for longitudinal movement in a well bore, FIGURE 1B forming a lower continuation of FIGURE 1A;

FIGURES 2A and 2B are views similar to FIGURES 1A and 1B except with various parts in expanded positions and the well packer set in a well casing;

FIGURE 3 is a developed view of a J-slot which can be used in controlling relative movement of parts of the well packer;

FIGURE 4 is a fragmentary, enlarged sectional view to illustrate the details of the force balancing system in accordance with the principles of the present invention;

FIGURE 5 is a cross section on line 55 of FIGURE 1A; and

FIGURE 6 is a fragmentary cross section on line 66 of FIGURE 5.

Referring initially to FIGURE 1, as well packer apparatus which embodies the principles of the present invention is illustrated with parts thereof in running-in positions. The well packer 10 includes a tubular mandrel 11 which is telescopically disposed within an anchor body 12 for sliding movement therein between the extended and contracted positions. The mandrel 11 has a central bore 13 and extends throughout the full length of the tool. A threaded collar 14 at the upper end of the mandrel 11 can adapt the mandrel for connection to a running-in string of tubing or drill pipe (not shown). The lower end of the mandrel 11 has a threaded pin portion 15 to which a section of pipe or another well tool can be connected. The mandrel bore 13 is arranged to continue the full bore size of the string to which the mandrel is connected.

The anchor body 12 can be conveniently formed by several tubular members which are threaded together in a fluid tight manner as shown in FIGURES 1A and 1B. Thus, an upper sub 17 forms the upper portion of the body 12 and has an inwardly extending flange 18 which is sealed against the exterior of the mandrel 11 by an O-ring 19 or the like. The flange 18 slidably engages the mandrel 11 between the collar 14 and an outwardly extending mandrel flange 16. The sub 17 is connected to an intermediate tubular body member 20 extending downwardly over the mandrel 11 to form an annular chamber 21. This tubular member 20 has an inwardly extending portion or flange 22 and is connected to a lower tubular body member 23 which forms a lower annular chamber 24 with the mandrel 11. An annular abutment ring 26 is threadedly connected to the lower member 23, and a reduced diameter compression sleeve 27 is coupled to the abutment ring. A pliant, elastomeric packing means 28 can be mounted around the compression sleeve 27 with the upper end of the packing means 28 engaging a downwardly facing annular shoulder 29 on the abutment ring 26. The lower end of the packing means engages the upper face of a lower annular abutment ring 30 which is slidable on the compression sleeve 27. The packing means 28 can take any conventional from such as a plurality of elastomeric packing rings separated by metallic gauge rings, the packing rings being adapted for lateral expansion upon compression thereof. The lower abutment ring 30 is connected to the upper end of a sleeve 31 which extends downwardly to an expander member 32. The expander member 32 and sleeve 31 can be co-rotatively and slidably secured to the compression sleeve 27 by means of coengaging splines 33 or the like. The expander member 32 has downwardly and inwardly inclined outer surfaces 34 thereon which are engageable with mating inner surfaces 35 on a plurality of slip members 36 in a manner whereby downward movement of the expander member relative to the slip members can cause outward shifting of the slip members.

Movably mounted at the lower end portion of the mandrel 11 is a tubular cage member 40. The upper portion of the cage 40 can have a J-slot recess 41 formed therein which is cooperable with a lug or projection 42 on the mandrel 11 for controlling relative movement between the cage and mandrel. The J-slot 41, shown in developed view in FIGURE 3, can have a long vertical segment 43 and a relatively short vertical segment 44, the segments 43 and 44 being connected by an inclined channel 45. The lug 42 engages in the short segment 44 when the parts are in a running-in position as shown in FIGURES 1A and 1B so that the cage member 40 cannot move substantially relative to the mandrel 11 in either longitudinal direction. When setting the tool, the mandrel 11 can be raised slightly and then lowered while applying right-hand torque thereto, causing the lug 42 to traverse the channel 45 ad enter the long segment 43, whereupon substantial downward movement of the mandrel 11 relative to the cage 40 is permitted.

Referring again to FIGURE 1B, the cage member 40 has a plurality of circumferentially spaced, radially directed recesses 47 in its outer periphery, each of the recesses receiving a typical drag block 48. The drag blocks are urged outwardly by springs 49 for frictional engagement with a well casing wall and function to retard movement of the cage member 40 within the well conduit in a conventional manner. Outward movement of the drag blocks 48 can be limited by annular bands 50 and 51 which are arranged to engage tangs 52 and 53, respectively, on each drag block 48. The lower end of the cage 40 is constituted by a guide sub 54, and it will be apparent that during vertical movement of the tool in a well bore the cage 40 is fixed relative to the mandrel 11 by virtue of engagement of the lug 42 within the slot segment 44 during lowering, and by engagement of the guide sub 54 with the mandrel pin 15 during retrieval.

A tubular housing member 56 can extend over the upper portion of the cage 40 to enclose the ]-slot and lug. The housing 56 can have an inwardly extending flange 57 and an annular spline 58 which engages in a companion groove 59 in the cage 40 to attach the housing to the cage. Suitable seals such as O-rings 60, 61 and 62 can be arranged to prevent debris or trash from entering into the interior of the cage 40 where the same might otherwise tend to foul the operation of the lug 42 within the J-slot 41. The interior of the cage 40 is opened to the well annulus by a port 63 to prevent the development of pressure differentials on the cage. If desired, the interior of the cage can be filled with a suitable heavy grease or the like to ensure easy operation of the tool.

The slip elements 36 can be pivotally connected on the upper end of the housing member 56 by reins 65 and pivot pins 66 in a conventional manner. Moreover, a conventional dovetail flange and groove connection 67 between each slip element 36 and the expander member 32 may be provided so that relative movemnt between the slip elements and the expander member will effect lateral movement of the slip elements to and from a well casing wall. Wickers or teeth 68 on the peripheral surfaces of each slip element 36 are formed to face downwardly and are adapted to bite into and grip a well casing to anchor the well packer 10 against downward movement therein. Tie bolts 69 located betwen adjacent slip segments 36 and connected to the expander member 32 and the housing member 56 can limit upward movement of the expander member relative to housing member 56 and the cage 40 to prevent damage to the slips, reins and pins in case an obstruction is encountered during lowering into a well.

An intermediate portion 71 of the mandrel 11 is spaced laterally away from the inner surface of the compression sleeve 27 to provide an annular fluid bypass passageway 72. The passageway 72 extends from a plurality of side ports 73 in the sleeve 31 to a plurality of bypass ports 74 which extend through the wall of the anchor body 12 above the packing 28 to provide ample area for bypassing well fluids through the packing. A bypass valve seat can take the form of an annular ring 75 which is threaded to the abutment ring 26. The seat ring 75 can have an external groove in which a suitable O-ring seal 76 is located to prevent fluid leakage.

For selectively closing off the bypass passageway 72, the mandrel 11 has an enlarged diameter section 78 to provide a valve head which is normally located above the seat ring 75 and above the bypass ports 74 when the mandrel is in its extended position as shown in FIG- URES 1A and 1B. In this relative position of parts, the bypass passageway 72 is open for bypassing well fluids through the packing means 28 as the well tool is shifted longitudinally in a well conduit. A suitable valve seal 79 is fitted into an external groove on the valve head 78 and is arranged to engage the inner seal surface 80 of the seat ring 75 when the mandrel 11 is moved to a lower or contracted position relative to the anchor body 12. In this position of parts, the bypass ports 74 are closed off to prevent fluid movement therethrough. Although the seal element 79 has been shown positioned on the valve head 78, it will be appreciated that the seal element 79 could be alternatively arranged in an appropriate internal annular groove in the seat ring 75 and adapted to seal against the external surface of the valve head 78 when the mandrel is moved downwardly.

As shown in FIGURE 1A, the intermediate member of the anchor body 12 is provided with a plurality of circumferentially spaced, generally rectangular shaped openings or windows 82, each of which receives a holding slip 83. Each holding slip 83 has an inner inclined surface 84 extending downward and inwardly toward the mandrel 11 and has upwardly facing wickers or teeth 85 on its outer periphery. Each slip 83 is slidably mounted on the anchor body 12 by a T shaped extension 86 which is received within a companion inclined groove 87 so that the holding slips can be shifted laterally between inner or retracted positions, as shown in FIGURE 1A, and outer or anchoring positions where the teeth 85 can grip a well conduit wall to prevent upward movement therein.

A hydraulically actuated slip expander member 90 is provided for shifting the holding slips 83 between their retracted and extended positions. The hydraulic member 90 is generally tubular in form and is arranged for longitudinal movement within the chamber 21 formed between this intermediate body member 20 and the mandrel 11. The chamber 21 is closed at its upper end by the top sub 17 and the seal ring 19. The bore of the hydraulic member 90 is sized for sliding reception on the mandrel 11 and an inner seal element 91 seals between the inner surface of the hydraulic member and the outer surface of the mandrel 11, while an outer seal element 92 seals between the outer periphery of the hydraulic member and the wall surface 93 of the chamber 21. The cross-sectional area A between the wall surface 93 and the outer surface of the mandrel 11 defines the effective area of the hydraulic member 90 on which fluid pressure can act.

The lower end portion of the hydraulic member 90 can have a plurality of longitudinally extending pockets 94, each of which receives a wedge-shaped expander insert 95. The expander inserts 95 can be rigidly but removably connected to the hydraulic member 90 by suitable fasteners such as threaded members 96. Each insert 95 can haves an inwardly extending portion 97 which engages in complementary recesses in the hydraulic member 90, to further secure the inserts for longitudinal movement with the hydraulic member. An outer surface 98 of each expander insert 95 is formed to incline downwardly and inwardly toward the mandrel 11 and is complementary in shape to the inner inclined surfaces 84 on the holding slips 83. Each slip 83 is arranged to engage a respective insert 95 in a manner whereby downward movement of the hydraulic member 90 will effect outward movement of the slips. Each holding slip 83 can further be slidably connected to a respective expander insert 95 by a conventional dovetail flange and groove arrangement 99 so that upward movement of the hydraulic member 90 will efiect inward retraction of the slips.

To enable fluid pressures within the mandrel 11 and below the well packer 10 to act on the upper side of hydraulic member 90, a pressure communicating passageway 101 can be formed to extend along the mandrel 11 from an opening 102 (FIGURE 1B) below the valve head 78 to an opening 103 which is in communication with the upper chamber 21 above the hydraulic member 90. Thus, it will be appreciated that such fluid pressures are communicated through the bypass passageway 72 and are reflected in the upper chamber 21 to act on the upper side of the hydraulic member 90. Also, fluid pressures existing in the well annulus above the packing element 28 are communicated through the anchor body openings 82 to act on the lower side of the hydraulic member 90. Accordingly, whenever the fluid pressure within the mandrel 11 exceeds the annulus pressure, the pressure difference acts on the effective area A as a force in a downward direction tending to move the hydraulic member downwardly and to expand the holding slips 83.

In order to prevent premature expansion of the holding slips 83 when the mandrel 11 is in its extended position for lowering or retrieving in a well bore, the mandrel is provided with several outwardly extending lugs or shoulders 105 as shown in FIGURES 5 and 6 which can be circumferentially offset relative to the slips 83. The shoulders 105 are slidably received in grooves 106 which extend longitudinally in the hydraulic member 90, the upper end of each groove 106 defining a downwardly facing shoulder 109 against which the upper face of a respective mandrel lug 105 can engage when the mandrel 11 is in its extended position. Accordingly, the hydraulic member 90 is positively retained in an upper or inactive position and cannot move downwardly to shift the holding slips 83 outwardly as long as the mandrel 11 is in its extended position within the anchor body 12. It will be appreciated that this structural arrangement prevents any possibility of premature actuation of holding slips 83 when the parts of the well packer are in relative positions for longitudinal movement in a well. However, when the well packer is set and the mandrel 11 is in its contracted position within the anchor body 12, the mandrel lugs 105 are moved downwardly away from the groove shoulders 107 a suflicient distance to permit free longitudinal movement of the hydraulic member 90 as it functions to actuate the holding slips 83.

The higher fluid pressures within and below the mandrel 11 also act on the mandrel itself in upward directions and tend to lift or pump the valve head 78 upwardly to an open position. This occurrence is undesirable because it would serve to open the bypass passageway 72 and equalize pressures on the well packer prematurely. Accordingly, and with particular reference to FIGURE 4, a force balancing system is provided in accordance with the present invention and comprises an annular piston 109 which can be integrally formed on the mandrel 1'1 and arranged for reciprocating motion within the lower chamber 24. A seal element 110 in a suitable groove around the outer periphery of the piston 109 engages a wall surface 111 of the chamber 24 to prevent fluid leakage past the piston. Also, an annular floating piston member 112 is positioned within the chamber 24 above the balance piston 109 with inner and outer seals 113 and 114 preventing fluid leakage past the floating piston, the inner seal engaging the outer periphery of the mandrel 11 and the outer seal engaging a wall surface 115 of the chamber 24. The effective area of the floating piston member 112 is defined by the differential area C between the wall surface 115 of the chamber 24 and the outer surface of the mandrel 11, and the effective area of the balance piston 109 is the area B between the wall surface 111 and the outer periphery of the mandrel 11. It will be appreciated that the floating piston 112 can move longitudinally within the chamber 24 between limits wherein the upper end of the piston engages the lower face of the flange 22, and wherein the lower end surface of a depending skirt 112a engages the upper face of the balance piston 109. The chamber space located between the balance piston 109 and the floating piston 112 is placed in communication with the pressure communicating passageway 101 by a lateral port means 116. Moreover, the upper end of the floating piston 112 is in communication with the well annulus above the packing means 2 8 via the anchor body openings 82, and the lower surface of the mandrel piston 119 is also in communication with the well annulus via the bypass ports 74 in the anchor body 12.

It will be noted that the wall surfaces 111 and 115 of the chamber 24 are on different diameters, the upper wall surface 115 being on the smaller diameter. Thus, the lower anchor body member 23 may be considered as forming respective cylinders in which the pistons 109 and 112 can function, the lower cylinder having a larger internal size than the upper cylinder. In accordance with the principles of the present invention, the balance piston 109 is sealed against the larger diameter lower wall surface 111, while the floating piston 112 is sealed against the smaller diameter upper wall surface 115. Therefore, another effective area D may be considered as being defined as the differential area between the lower chamber wall surface 111 and the upper chamber wall surface 115. The various parts of the balancing system are relatively sized such that this differential area D is made substantially equal to the difference in areas between the inner surface 80 of the valve seat ring 75, against which the bypass seal element 79 seals when the mandrel 11 is in contracted position, and the outside surface of the tubing string (not shown) on which the tool is lowered into the well. This area is shown for convenience of illustration in FIGURE 4 as E. A typical example of this area might be where the tool is run on 2% OD. tubing, and the bore through the seat ring 75 is about 2%. Therefore, the differential area E would be about two square inches, and thus the differential area D will be designed to be the same. The advantages derived from this particular construction will be more fully explained in the following description of the operation of the present invention.

Operation The parts of the well packer 10 are assembled as shown in FIGURES 1A and 1 B and the mandrel 11 coupled to a running-in string of tubing or drill pipe for lowering into a Well casing. During lowering, the cage is retained in its lower position on the mandrel .11 by engagement of the lug 42 within the short vertical segment 44 of the J-slot 41. The drag blocks 48 can slide along in frictional engagement with the well casing wall and the lower slips 36 are maintained in retracted positions because the cage member 40 cannot move relatively upwardly toward the expander member 32. The packing 28 is unexpanded and the valve head 78 on the mandrel 11 is spaced above the bypass seat ring 75 so that well fluids can enter the bypass passageway 72 through the lower side ports 73 and exit through the upper bypass ports 74.

The hydraulic member 90 is held in its upper or inactive position by the mandrel shoulders 105 and therefore cannot move downwardly in a manner to actuate the holding slips 83 outwardly. Accordingly, it will be appreciated that although the holding slips 83 can be eventually hydraulically operated, they are positively prevented from being prematurely operated by fluid pressure surges which can be developed within the well packer during rapid descent into a fluid filled well bore.

At setting depth, the well packer is halted. A small upward movement of the mandrel 11 and then downward movement of same coupled with right-hand torque will position the lug 42 within the long vertical J-slot segment 43 to permit substantial downward movement of the mandrel 11 relative to the cage member 40 for setting the well packer. During the downward movement of the mandrel 11, the slips 36 and the cage member 40 are held against downward movement by the drag blocks 48. Accordingly, downward movement of the mandrel 11 will advance the expander member 32 downwardly relative to the slips 36 to shift them outwardly into gripping engagement with the well casing P as shown in FIGURE 2B. Further mandrel movement will move the valve head 78 and seal element 79 within the seat ring 75 to close the bypass ports 74 to fluid flow and to engage the mandrel collar 14 with the upper flange 18 on the anchor body 12 so that the weight of the tubing string can be imposed upon the anchor body.

Inasmuch as the lower abutment ring 30 is supported against further downward movement by the slips 36, the weight of the tubing string can be transmitted through the anchor body 12 to the upper end of the packing element 28. As weight is applied, the upper abutment ring 26 will be advanced toward the lower abutment ring 30 to compress and expand the packing 28 outwardly into sealing engagement with the surrounding well casing wall as shown in FIGURE 2. The weight of the tubing string can be maintained on the well packer to maintain its set condition.

It will be noted that when the well-packer is set and the bypass ports 74 closed off by the valve head 78, the lower opening 102 of the pressure communicating passageway 101 is in communication with the bypass passageway 72 so that whatever fluid pressures exist within the mandrel bore 13 and in the well bore below the expanded packing element 28 are communicated through the bypass passageway 72, the pressure communicating passageway 101 and to the upper side of the hydraulic member via the opening 103. Moreover, the pressure is also communicated to a location between the balance piston 109 and the floating piston 112 via the port means 116. As previously mentioned, fluid pressures existing in the well annulus above the expanded packing element 28 can act on the lower side of the hydraulic member 90 through the holding slip 'windows 82, on the lower face of the balance piston 109 through the bypass ports 74, and on the upper face of the floating piston 112 'via the holding slip windows 82.

An operation such as squeeze cementing, acidizing, or hydraulic fracturing can now be performed in an interval below the packer 10. Multiple operations, including a testing operation can also be undertaken by using in combination with the well packer 10, a well tool such as that shown in US. Patent No. 3,065,796, Nutter. Such well tools have a removable center section with a main valve for testing earth formations. If, as is usually the case during an operation such as squeeze cementing, tubing pressure should exceed annulus pressure, the pressure difference will attempt to force the well packer 10 upwardly within the casing P as well as attempting to move the mandrel 11 upwardly. However, the high tubing pressure is also acting on the upper side of the hydraulic member 90, while the lower annulus pressure is acting on the lower side of the hydraulic member. Accordingly, the pressure difference will act On the area A as a downward force to move the hydraulic member 90 downwardly and thus shift the holding slips 83 into gripping engagement with the well casing as shown in FIGURE 2A, thereby preventing upward movement of the well packer 10. The greater the pressure difference, the greater the holding force of the slips 83. Moreover, the higher tubing pressure is communicated into the annular chamber 24 to act downwardly on the upper face of the mandrel balance piston 109, while the lower annulus pressure is acting on the lower face of the balance piston. Accordingly, the pressure difference will act on the area B as a downward force tending to counterbalance the upward force on the mandrel 11 due to high tubing pressure, thereby substantially minimizing the net upward force on the mandrel and preventing upward movement of the mandrel during a pressure operation. The pressure differential is also acting upwardly on the area C of the floating piston 112, but the floating piston can merely shift upwardly into engagement with the anchor body flange 22 as shown in FIGURE 2B. Since the anchor body 12 is anchored against upward movement by the holding slips 83, the upward force on the floating piston 112 is of no consequence.

In a case where annulus pressures exceed tubing pressures, for example, where fluid is lifted within the tubing by swabbing to test the success of an acidizing operation, or where the well interval below the packer is placed at atmospheric or other low pressure to test the operation of a bridge plug or the like therebelow (commonly called a dry test in this art) the higher annulus pressure acts downwardly on the well packer 10 in a conventional manner to set the packing element 28 and the lower slips 36 even more tightly within the well casing P. The higher annulus pressure will tend to lift the hydraulic member 90 upwardly within the anchor body 12 since the lower tubing pressure is acting on the upper side of the hydraulic expander member. Under these influences, the hydraulic member 90 can move upwardly until its upper end surface engages the top sub 17. This movement will retract the holding slips 83, which are not needed anyway where annulus pressures exceed tubing pressures. Since the lower tubing pressure is now acting on the upper face of the balance piston 109 and the higher annulus pressure on the lower face thereof, there is an upward force on the area B of the balance piston 109. However, the pressure difference is now acting downwardly on the area C of the floating piston 112 which can move downwardly as shown in FIGURE 4 until the skirt 112a engages the balance piston 109, the downward force on the piston 112 opposing the upward force on the piston 109. The pressure difference is also acting downwardly on the area difference E between the bore area of the bypass seat ring 75 and the running-in string. However, the high annulus pressures are acting upwardly on the area difference D between the mandrel balance piston 109 and the floating piston 112. When the areas D and E are the same, there will be no substantial net force on the mandrel 11 due to pressure tending to move it in either direction. Accordingly, to open the bypass passageway 72 and equalize pressures to release the packer, only the weight of the running-in string need be lifted at the surface to move the mandrel upwardly.

As a typical example, the packer 10 might be sized for setting in 5 casing or liner at a depth of 12,000 feet below the surface in 14 pound mud. Accordingly, there would be approximately 8,700 psi. hydrostatic annulus pressure at the packer. If the bypass seal area (inner surface 80 of seat ring 75) is about 2.875 inches in diameter, and the tubing string has a 2.375 inch outside diameter, the area B will be about two square inches. Thus, in the case of a dry test there will be approximately 17,400 pounds of force acting downwardly on the mandrel 11 due to annulus pressure. However, if the area diflference D is made equal to two square inches, the net force due to the coaction of the balance pistons 109 and 112 will be 17,400 pounds acting upwardly on the lower piston 109. Therefore, there will be no substantial net force on the mandrel itself which will add to the total strain above the weight of the running-in string which must be applied at the surface in order to open the bypass passageway 72 and equalize pressures on the packer 10.

Moreover, it will be appreciated that the force balancing system of the present invention can be utilized in a larger size packer, such as for 7" casing, and permit the packer to run on relatively small tubing such as 2% 0D. This is because the various pistons and cylinders can be selectively sized such that the area D is the same as the correspondingly larger area E in this case. Accordingly, there is no risk of overstraining and parting the tubing when attempting to open the bypass passageway 72 when high annulus pressures exit.

To retrieve the packer 10 from the well, the mandrel 11 is lifted upwardly by the running-in string. If the holding slips 83 are not already retracted by higher annulus pressure as previously described, upward movement of the mandrel 11 will engage the mandrel shoulders 107 with the hydraulic member 90 and thus shift it upwardly to retract the holding slips 83. Also, upward movement of the mandrel 11 will position the valve head 78 above the bypass seat ring 75 to open the bypass ports 74 and permit equalization of any existing pressure differentials across parts of this packer. As compressive force is removed from the packing 28, it will inherently retract and eventually the lower expander member 32 will be moved upwardly relative to the lower slip elements 36 to cause their release and retraction. When suflicient upward mandred movement has occurred, the cage member 40 will occupy its initial lower position relative to the mandrel 11 and the lug 42 will again engage in the short slot segment 44 to re-jay and lock the packer parts in retracted positions for longitudinal movement in the casing P. If desired, a coil compression spring can be placed between the balance piston 109 and the upper end of the seat ring 75 to help overcome seal or other friction forces and enable easy return of the mandrel 11 to upper re-jayed position relative to the cage 40.

A well packer has been disclosed which can be anchored in a well conduit against movement in either longitudinal direction. The well packer incorporates a new and improved force balancing system which operates to prevent undesired opening of the bypass during a pressure operation where tubing pressures are high, and which permits opening the bypass when desired even under extreme pressure conditions where annulus pressures are high. Accordingly, the well packer of the present invention can be operated safely at greater depths in a well than has heretofore been known in the art.

Certain changes or modifications may be made in the disclosed embodiment of the present invention without departing from the inventive concepts involved. For example, although in the particular embodiment shown the floating piston 112 has a skirt 112a which abuts against the balance piston 109 to enable transfer of force from the floating piston to the mandrel 11, it will be appreciated that other arrangements could be used, such as mandrel shoulders or the like, to effect such force transfer as will be apparent to those skilled in the art in view of this disclosure. Moreover, although the balance piston 109' is disclosed as integral with the mandrel 11, it will be appreciated that the piston could be slidable on the mandrel as long as it is coupled to the mandrel when the packer is set. Accordingly, it is intended that the appended claims cover all such changes or modifications falling within the true spirit and scope of this invention.

I claim:

1. A force balancing system for use in a retrievable well packer having a mandrel subject to pressure in a well, comprising: a body member mounted about said mandrel, said body member providing first and second cylinder means having different diameters; first piston means on said mandrel sealingly engaging one of said cylinder means; second piston means movable relative to said mandrel and the other of said cylinder means and sealingly engaging said mandrel and said other cylinder means; means to enable fluid pressures in the mandrel to act on said first piston means; means to enable fluid pressures other than those in the mandrel to act on said second piston means; and means for transmitting force on said second piston means to said mandrel.

2. The system of claim 1 wherein said transmitting means includes said first piston means.

3. The system of claim 2 wherein said transmitting means further includes a member on said second piston means capable of engaging the side of said first piston means on which said pressures in said mandrel act.

4. In a well packer having a body and a mandrel adapted for connection to a pipe string and movably disposed in said body, said well packer further having packing means for packing off the annulus between the pipe string and a well conduit, and further having valve means for controlling fluid flow through a passage extending between locations above and below said packing means, said valve means providing said mandrel with an upwardly facing transverse surface which is subject to fluid pressure in said annulus, the improvement comprising: hydraulic means having a resultant downwardly facing transverse surface which is subject to fluid pressure in said annulus,

said downwardly facing surface having an area substantially equal to the area of said upwardly facing surface for counterbalancing the force on said mandrel due to greater fluid pressure in said annulus; and means for enabling fluid pressure in the annulus to act on said hydraulic means.

5. In a well packer having a mandrel adapted for connection to a tubing string extending to the top of a well bore, and a packing assembly which can be expanded to seal off the annulus between the well casing and the tubing string, said mandrel being movable between extended and contracted positions within said packing assembly, the improvement comprising: first piston and cylinder means responsive to higher fluid pressure in the tubing for exerting downward force on said mandrel; second piston and cylinder means responsive to higher pressure in the annulus between the tubing and casing above said packing assembly for exerting downward force on said first piston means, said second cylinder means having a vertical extent at least as long as the distance said mandrel moves between said extended and contracted positions, said second piston means having a smaller effective pressure area than said first piston means; and means for transmitting force on said second piston means to said mandrel.

6. In a retrievable well packer apparatus having a mandrel adapted for connection to a running-in string, a packer assembly for packing off a well bore, a fluid passage for bypassing well fluids past the packing assembly, and valve means including coengageable means actuated by movement of the mandrel by the running-in string for opening and closing the passage, the combination comprising: first hydraulic means on which fluid pressure in said mandrel can act for exerting force on said mandrel in one longitudinal direction when the tubing pressure is higher than the pressure in the annulus above said packing means; and second hydraulic means on which fluid pressure in the well annulus above said packing assembly can act for exerting force on said mandrel in said one longitudinal direction when the annulus pressure is higher than the tubing pressure, said first and second hydraulic means having diflerent effective pressure areas, the difference in effective pressure areas between said first and second hydraulic means being substantially equal to the difierence in areas between said coengageable means and said running-in string.

7. A well packer apparatus comprising: an anchor body; packing means mounted about said body and adapted to be compressed and thereby expanded into sealing engagement with a Well bore wall; anchor means including slip and expander means for anchoring against movement in the well bore; a mandrel adapted for connection to a running-in string and telescopically movable in said anchor body between extended and contracted positions; a bypass passageway extending between portions of said anchor body and said mandrel to locations above and below said packing means; valve means including coengageable means between said anchor body and mandrel when the mandrel is in contracted position for closing off said bypass passageway; chamber means between said anchor body and said mandrel above said coengageable means; a first piston means on said mandrel sealingly and slidably movable in said chamber means; means to enable fluid pressure in said running-in string to act downwardly on said first piston means; means to enable fluid pressure in the well annulus above said packing means to act upwardly on said first piston means; a second piston means sealingly and slidably received in said chamber means and movable downwardly therein to a position engaging said first piston means; means to enable fluid pressure in said running-in string to act upwardly on said second piston means; means to enable fluid pressure in the well annulus above said packing means to act downwardly on said second piston means; the difference in cross-sectional areas between said first and second piston means being substantially the same as the difference in cross-sectional areas between said coengageable means and said running-in string.

8. The well packer apparatus of claim 1 wherein said second piston means has a smaller effective pressure area than said first piston means.

References Cited UNITED STATES PATENTS 2,878,877 3/1959 Baker 166-120 X 3,020,959 2/1962 Nutter 166134 3,189,095 6/1965 De Rochemont 166-120 3,233,675 2/1966 Tamplen et al. 166120 3,277,965 10/1966 Grimmer 16612() 3,338,308 8/1967 Elliston et al. 166120 3,387,658 6/1968 Lebourg 166129 X DAVID H. BROWN, Primary Examiner.

US. Cl. X.R. 166-420, 134 

